U.S. patent application number 14/411497 was filed with the patent office on 2015-06-04 for multi -axial induction borehole imager.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is Ferhat T. Celepcikay, Burkay Donderici, Luis E. San Martin. Invention is credited to Ferhat T. Celepcikay, Burkay Donderici, Luis E. San Martin.
Application Number | 20150153474 14/411497 |
Document ID | / |
Family ID | 49783710 |
Filed Date | 2015-06-04 |
United States Patent
Application |
20150153474 |
Kind Code |
A1 |
Donderici; Burkay ; et
al. |
June 4, 2015 |
MULTI -AXIAL INDUCTION BOREHOLE IMAGER
Abstract
Various systems and methods are disclosed for implementing and
using a multi-axial induction borehole imaging tool that includes
emitters that induce, at azimuthally-spaced positions on a borehole
wall, a plurality of fields having components in three non-coplanar
directions within a formation. The tool also includes directionally
sensitive inductive sensors that sense the components caused by
each of the one or more inductive emitters, and a downhole
controller that processes signals received from the directionally
sensitive inductive sensors to provide a set of measurements
representative of an impedance tensor at each position.
Inventors: |
Donderici; Burkay; (Houston,
TX) ; Celepcikay; Ferhat T.; (Houston, TX) ;
San Martin; Luis E.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Donderici; Burkay
Celepcikay; Ferhat T.
San Martin; Luis E. |
Houston
Houston
Houston |
TX
TX
TX |
US
US
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
49783710 |
Appl. No.: |
14/411497 |
Filed: |
June 29, 2012 |
PCT Filed: |
June 29, 2012 |
PCT NO: |
PCT/US2012/044945 |
371 Date: |
December 27, 2014 |
Current U.S.
Class: |
324/339 |
Current CPC
Class: |
G01V 3/38 20130101; G01V
3/28 20130101; E21B 47/13 20200501; G01V 3/108 20130101 |
International
Class: |
G01V 3/38 20060101
G01V003/38; E21B 47/12 20060101 E21B047/12; G01V 3/28 20060101
G01V003/28 |
Claims
1. A multi-axial induction borehole imaging tool that comprises:
one or more inductive emitters that induce, at azimuthally-spaced
positions on a borehole wall, a plurality of fields having
components in three non-coplanar directions within a formation; one
or more directionally sensitive inductive sensors that sense the
components caused by each of the one or more inductive emitters;
and a downhole controller that processes signals received from the
one or more directionally sensitive inductive sensors to provide a
plurality of measurement sets, wherein each measurement set is
representative of an impedance tensor at each of said
azimuthally-spaced positions on the borehole wall.
2. The tool of claim 1, which further comprises: one or more
bucking coils each positioned between an inductive sensor of the
one or more inductive sensors and an inductive emitter of the one
or more inductive emitters; wherein the components each comprise a
directly coupled component and a formation coupled component; and
wherein each bucking coil generates a second signal that
substantially cancels a portion of signals received from the
inductive sensor and representative of the directly coupled
component.
3. The tool of claim 1, wherein at least one of the one or more
inductive sensors is vertically spaced away from at least one of
the one or more inductive emitters by less than or equal to one
inch.
4. The tool of claim 1, wherein the one or more inductive emitters
comprise three orthogonal coils.
5. The tool of claim 1, wherein the one or more inductive sensors
comprise three orthogonal coils.
6. The tool of claim 1, wherein the impedance tensor indicates one
or more electrical anisotropy characteristics of the formation.
7. The tool of claim 1, wherein the impedance tensor comprises a
3.times.3 tensor.
8. The tool of claim 1, wherein said plurality of fields are
electrical fields.
9. The tool of claim 1, wherein said plurality of fields are
magnetic fields.
10. A multi-axial induction borehole imaging system that comprises:
a tool body that moves along a borehole through a formation with
one or more transducer pads to measure a formation impedance tensor
as a function of borehole depth and azimuth angle on the borehole
wall, wherein each transducer pad comprises a set of one or more
inductive emitters and sensors that respectively induce and sense
one or more fields within the formation, wherein the inductive
sensors provide signals representative of three
linearly-independent directional components of the one or more
fields; a downhole controller that processes the signals to provide
a plurality of measurement sets, wherein each measurement set is
representative of an impedance tensor at the borehole depth and
azimuth angle at which each measurement set is acquired; and a
computer system that receives and derives from the measurement sets
one or more formation characteristics associated with each borehole
depth and azimuth angle and further presents to a user data
representative of at least one of the one or more formation
characteristics.
11. The system of claim 10, wherein the transducer pads are
embedded in the tool body.
12. The system of claim 10, wherein the transducer pads couple to
and extend away from a central portion of the tool body towards the
borehole wall.
13. The system of claim 10, wherein the controller further derives
a mud resistivity and a standoff distance between each of the one
or more transducer pads and the borehole wall for each borehole
depth and azimuth angle.
14. The system of claim 10, wherein operation of a first grouping
of the one or more inductive emitters and the one or more inductive
sensors is multiplexed with operation of a second grouping of the
one or more inductive emitters and the one or more inductive
sensors.
15. The system of claim 14, wherein the operations of the first and
second groupings are multiplexed using a multiplexing technique
selected from the group consisting of time division multiplexing,
frequency division multiplexing and code division multiplexing.
16. The system of claim 14, wherein the first and second groupings
share at least one common inductive sensor.
17. A multi-axial induction borehole imaging method that comprises:
lowering a multi-axial induction borehole imaging tool into a
borehole through a formation; at each of multiple azimuthal angles
on the borehole wall, inductively inducing fields having three
linearly-independent directional components within a formation;
inductively detecting the directional field components to obtain a
plurality of measurement sets, wherein each measurement set is a
function of azimuthal angle and depth in the borehole, and is
further representative of an impedance tensor; deriving from the
measurement sets one or more formation characteristics as a
function of the azimuthal angle and depth in the borehole; and
presenting to a user data representative of at least one the one or
more borehole characteristics.
18. The method of claim 17, further comprising: inductively
detecting a directly coupled component of each of the directional
field components; combining a signal representative of the inverse
of each directly coupled component with a signal representative of
each corresponding directional field component, producing one or
more difference signals; and deriving the measurements from the one
or more difference signals.
19. The method of claim 17, wherein the one or more formation
characteristics comprise a characteristic selected from the group
consisting of a vertical formation resistivity, one or more
horizontal formation resistivities, a formation dip, and a
formation strike.
20. The method of claim 17, wherein the impedance tensor comprises
a 3.times.3 tensor.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is related to co-pending application serial
no. PCT/U.S. Ser. No. 12/44,931 (Atty Dkt 2012-IP-058456) titled
"Full Tensor Micro-Impedance Imaging," which is hereby incorporated
by reference.
BACKGROUND
[0002] Oil field operators demand access to a great quantity of
information regarding the parameters and conditions encountered
downhole. A wide variety of logging tools have been and are being
developed to collect information relating to such parameters as
position and orientation of the bottom hole assembly, environmental
conditions in the borehole, and characteristics of the borehole
itself as well as the formations being penetrated by the borehole.
Among such tools are resistivity logging tools, which measure the
electrical resistivity of a formation within a borehole. These
tools cause electrical currents to flow within the formations to
determine the formation's resistivity. A high resistivity
measurement within a porous formation can indicate that
hydrocarbons are present in the formation.
[0003] The electrical resistivity of a formation is generally
anisotropic, i.e., the formation's resistivity will vary depending
upon the orientation of an electrical current flowing through the
formation. The measurements obtained by a resistivity logging tool
may thus vary depending upon the orientation of the current induced
in the formation and used by the tool to measure the formation's
resistivity. Further, both macro-anisotropy (i.e., anisotropy
caused by differing formation layers) and micro-anisotropy (i.e.,
anisotropy caused by the grains that make up the material of each
layer) may both be present. The micro-anisotropy of a given
formation layer, however, may not be detectable by resistivity
logging tools with measurement resolutions measured in feet or
meters, rather than inches or centimeters. Such low resolution
tools may thus not fully characterize the anisotropy of the
formation at both a micro and a macro level, producing an
incomplete and possibly misleading characterization of the
formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Accordingly, there are disclosed in the drawings and the
following detailed description specific embodiments of multi-axial
induction borehole imaging tools and methods. In the drawings:
[0005] FIG. 1 shows an illustrative logging while drilling
environment.
[0006] FIG. 2 shows an illustrative wireline logging
environment.
[0007] FIG. 3 shows an illustrative tubing-conveyed logging
environment.
[0008] FIGS. 4A-4B show illustrative logging while drilling and
wireline logging tools.
[0009] FIG. 5 shows an illustrative transducer pad.
[0010] FIGS. 6A-6C show an illustrative sequencing of
transducers.
[0011] FIG. 7 graphs an illustrative sequencing of transducers.
[0012] FIG. 8 shows an illustrative inductive transducer pad.
[0013] FIG. 9 shows an illustrative galvanic transducer pad.
[0014] FIG. 10 shows an illustrative computer and data acquisition
system.
[0015] FIG. 11 shows an illustrative data flow for deriving
anisotropy data.
[0016] FIG. 12 shows an illustrative set of graphical borehole
logs.
[0017] FIG. 13 shows an illustrative method for operating an
electrical anisotropy borehole imaging system.
[0018] It should be understood, however, that the specific
embodiments given in the drawings and detailed description do not
limit the disclosure. On the contrary, they provide the foundation
for one of ordinary skill to discern the alternative forms,
equivalents, and modifications that are encompassed together with
one or more of the given embodiments in the scope of the appended
claims.
DETAILED DESCRIPTION
[0019] The paragraphs that follow describe illustrative multi-axial
induction borehole imaging tools and systems, as well as methods
for using such tools and systems. Various environments suitable for
the use of these tools, systems and methods are first described,
followed by two example tools. The emitter/sensor pads of these
tools are then functionally described, and specific inductive and
galvanic transducer pad embodiments are subsequently described.
Illustrative galvanic electrode configurations are also shown and
described. An illustrative system, including both surface and
downhole components, is then described together with the flow of
data through the system that produces the imaging data. Examples
illustrate how the imaging data may be presented as one or more
graphical logs. Finally, an illustrative method for using the
described tools and systems is described.
[0020] FIG. 1 shows an illustrative logging while drilling (LWD)
environment. A drilling platform 2 supports a derrick 4 having a
traveling block 6 for raising and lowering a drill string 8. A
kelly 10 supports the drill string 8 as it is lowered through a
rotary table 12. A drill bit 14 is driven by a downhole motor
and/or rotation of the drill string 8. As bit 14 rotates, it
creates a borehole 16 that passes through various formations 18. A
pump 20 circulates drilling fluid through a feed pipe 22 to kelly
10, downhole through the interior of drill string 8, through
orifices in drill bit 14, back to the surface via the annulus
around drill string 8, and into a retention pit 24. The drilling
fluid transports cuttings from the borehole into the pit 24 and
aids in maintaining the borehole integrity.
[0021] An LWD tool 26 is integrated into the bottom-hole assembly
near the bit 14. As the bit extends the borehole through the
formations, logging tool 26 collects measurements relating to
various formation properties as well as the tool orientation and
various other drilling conditions. The logging tool 26 may take the
form of a drill collar, i.e., a thick-walled tubular that provides
weight and rigidity to aid the drilling process. A telemetry sub 28
may be included to transfer measurement data to a receiver within
surface module 30, which forwards the data to computer system 31
for further processing. Telemetry sub 28 may also receive commands
from surface module 30 originated from computer system 31. Data
and/or commands may be transferred between surface module 30 and
computer system 31 wirelessly (as shown), or via electrical
conductors and/or optical cables (not shown).
[0022] At various times during the drilling process, the drill
string 8 may be removed from the borehole as shown in FIG. 2. Once
the drill string has been removed, logging operations can be
conducted using a wireline logging tool 34, i.e., a sensing
instrument sonde suspended by a cable 42 deployed from reel 43 and
having conductors for transporting power to the tool and telemetry
from the tool to the surface (as shown). A wireline logging tool 34
may have pads and/or centralizing springs (not shown) to maintain
the tool near the axis of the borehole as the tool is pulled
uphole. The pads may also house transducers used to determine at
least some characteristics of the surrounding formation, as
described in more detail below. A surface logging facility 44
collects measurements from the logging tool 34, and includes a
surface module 30 coupled to spool 43 and a computer system 45 for
processing and storing the measurements gathered by the logging
tool. In at least some alternative embodiments, telemetry may be
communicated between the tool and computer system 45 wirelessly
(not shown).
[0023] An alternative logging technique is logging with coil
tubing. FIG. 3 shows an illustrative coil tubing-conveyed logging
system in which coil tubing 54 is pulled from a spool 52 by a
tubing injector 56 and injected into a well through a packer 58 and
a blowout preventer 60 into the well 62. (It is also possible to
perform drilling in this manner by driving the drill bit with a
downhole motor.) In the well, a supervisory sub 64 and one or more
logging tools 65 are coupled to the coil tubing 54 and optionally
configured to communicate to a surface computer system 66 via
information conduits or other telemetry channels (e.g. via
electrical conductors, optical fibers, or wirelessly). An uphole
interface 67 may be provided to exchange communications with the
supervisory sub and receive data to be conveyed to the surface
computer system 66.
[0024] Surface computer system 66 of FIG. 3 is configured to
communicate with supervisory sub 64 during the logging process or
alternatively configured to download data from the supervisory sub
after the tool assembly is retrieved. Surface computer system 66 is
preferably configured by software (shown in FIG. 3 in the form of
removable storage media 72) to process the logging tool
measurements. System 66 includes a display device 68 and a
user-input device 70 to enable a human operator to interact with
the system software 72.
[0025] In each of the foregoing logging environments, the logging
tool assemblies preferably include a navigational sensor package
that includes directional sensors for determining the inclination
angle, the horizontal angle, and the rotational angle (a.k.a. "tool
face angle") of the bottom hole assembly. As is commonly defined in
the art, the inclination angle is the deviation from vertically
downward, the horizontal angle is the angle in a horizontal plane
from true North, and the tool face angle is the orientation
(rotational about the tool axis) angle from the high side of the
borehole. In accordance with known techniques, directional
measurements can be made as follows: a three axis accelerometer
measures the earth's gravitational field vector relative to the
tool axis and a point on the circumference of the tool called the
"tool face scribe line". (The tool face scribe line is typically
drawn on the tool surface as a line parallel to the tool axis.)
From this measurement, the inclination and tool face angle of the
logging assembly can be determined. Additionally, a three axis
magnetometer measures the earth's magnetic field vector in a
similar manner. From the combined magnetometer and accelerometer
data, the horizontal angle of the logging assembly can be
determined. These orientation measurements, when combined with
measurements from motion sensors, enable the tool position to be
tracked downhole.
[0026] In these and other logging environments, measured parameters
are usually recorded and displayed in the form of a log, i.e., a
two-dimensional graph showing the measured parameter as a function
of tool position or depth. In addition to making parameter
measurements as a function of depth, some logging tools also
provide parameter measurements as a function of rotational angle.
Such tool measurements can be displayed as two-dimensional images
of the borehole wall, with one dimension representing tool position
or depth, the other dimension representing azimuthal orientation,
and the pixel intensity, pattern or color representing the
parameter value.
[0027] Among the measured parameters that may be presented as part
of a log are resistivity measurements, which can include
measurements that reflect the anisotropy of the borehole formation.
Such measurements include, but are not limited to, vertical
resistivity, horizontal resistivities in one or more directions,
formation dip and formation strike. FIGS. 4A-4B show illustrative
downhole tools suitable for taking such measurements. Illustrative
LWD tool 400A (FIG. 4A) includes an array 402 of transducers 404.
Each transducer 404 may include an emitter, a sensor or both, as
well as additional structures and electronics as described in more
detail below. The transducers 404 are positioned either inside
cavities within drill collar 406 or embedded in non-conductive
sections of the collar. Techniques for placing transducers on and
within drilling pipes and collars are well known in the art and are
not discussed further. Alternatively, an array 402 with fewer
transducers 404 (e.g., a single vertical line of transducers) may
be used, with the timing of measurements being arranged to exploit
the drillstring's rotation to produce measurements at multiple
azimuthal locations around the borehole as drilling proceeds.
[0028] FIG. 4B shows illustrative wireline logging tool 400B, which
includes eight transducer pads 408. Each transducer pad includes
transducers 404 similar to those used with LWD tool 400A.
Transducer pads 408 are extended from the main body 410 of wireline
logging tool 400B by standoffs that position transducer pads 408
near or against the borehole wall. This reduces the effect of the
drilling fluid on the measurements and also provides better
coupling between transducers 404 and the formation. Such improved
coupling, together with a reduced spacing of transducers relative
to other logging tools, helps to improve the sensitivity of the
tool and the resolution of the log image produced.
[0029] FIG. 5 shows an illustrative transducer pad 500 with its
rear cover 502 separated from its front face 504. The interior
components of transducer pad 500 are shown in a simplified form for
purposes of the discussion that follows. The illustrative
components include an emitter transducer array 520 that includes
emitters 522-526, and a sensor transducer array 510 that includes
sensors 512-516. Each emitter transducer is configured and oriented
to operate along a specific axis. Thus, for example, if emitter 526
is an inductive emitter, emitter 526 will produce a magnetic or
B-field within the formation in front of transducer pad 500 with an
orientation substantially along the Z axis (vertical). Similarly,
each sensor transducer is also configured and oriented to operate
along a specific axis. Thus, for example, if sensor 514 is an
inductive sensor, sensor 514 will be most sensitive to B-fields
within the formation with an orientation along the X axis (i.e.,
perpendicular to front face 504). These orientations of emitters
and sensors also apply to the electric field orientations induced
and sensed within the formation by capacitive emitters and sensors,
and to the orientations of electric currents injected into and
sensed within the formation by galvanic emitters and sensors.
Although shown as separate elements for purposes of the present
discussion, in at least some embodiments a single multi-axial
emitter and a single multi-axial sensor may be implemented to emit
and sense separable electric fields, magnetic fields or electrical
currents in more than one direction.
[0030] Continuing to refer to FIG. 5, by configuring the emitters
and sensors as shown it is possible to generate multiple sets of
independent measurements, each set including multiple concurrent
measurements. More specifically, the orthogonal configuration of
the emitters and sensors shown allows three sets of three
measurements each to be acquired for a given borehole depth and
azimuth angle, generating nine samples organized as a 3.times.3
measurement tensor. It should be noted that the same concept can
also apply for non-orthogonal sensors, as long as the excitations
generated are linearly independent (i.e., non-coplanar).
Non-orthogonality can be incorporated by including it in a forward
model and an inversion process (both described in more detail
below), or by synthesizing orthogonal signals by rotation and using
the orthogonal processing algorithms. Each set can be generated by
separately energizing and de-energizing each emitter in turn while
acquiring concurrent samples from each of the three sensors for the
time period during which each emitter is energized. An example of
such a sequence is shown in FIGS. 6A through 6C, and graphed in
FIG. 7.
[0031] In FIG. 6A, energized emitter 524 (shown highlighted)
induces a time-variant B-field 602 within the surrounding formation
primarily along the X axis. As B-field 602 extends into the
anisotropic formation, it begins to curve in the other two
directions, which does produce some components in the Y and Z
directions. As a result, each of the three enabled sensors 512, 514
and 516 (also highlighted) detect a respective time-variant B-field
along the X, Y and Z axes, each with differing magnitudes. This is
reflected in the graph of FIG. 7 during sample period T1, wherein
the B-field induced by the X emitter (Emit X) is detected primarily
by the X sensor (Sens X), with detectable contributions measured by
the Y and Z detectors (Sens Y and Sens Z). Once samples have been
acquired during sample period T1, the X emitter is de-energized and
the Y emitter is energized, as shown in FIG. 6B. This time a
B-field 604 is induced that is oriented primarily along the Y axis.
The resulting detected signals by the X, Y and Z sensors are shown
in FIG. 7 during sample period T2. The sequence is again repeated
along the Z axis to produce B-field 606 as shown in FIG. 6C, with
the resulting detected signals shown in FIG. 7 during sample period
T3.
[0032] The foregoing measurement technique employs a
time-multiplexing principle to separate the effects of the various
emitters. Other multiplexing principles would also be suitable,
including frequency multiplexing and code-division modulation.
[0033] FIG. 8 shows an illustrative three-element multi-axial
(i.e., tri[[-]]axial) micro-inductive transducer pad 800 that
operates as described above. Within emitter 820, emitter
electronics module 822 couples to and drives each of the emitter
coils 824 with an alternating current, under the control of other
electronics and/or software within the tool body (not shown) to
which emitter electronics module 822 also couples. The illustrated
emitter coils are coupled to a common node and positioned such that
the time-variant B-field produced by one emitter coil is orthogonal
to the time-variant B-fields of the other two emitter coils. In at
least some embodiments, two of the emitter coils are oriented such
that their B-fields are parallel to the pad surface facing the
borehole wall (or with their B-fields tangential to at least one
common point on the pad surface for curved pads). Sensor
electronics module 812 within sensor 810 is similarly coupled to
each of sensor coils 814, and receives electrical signals from the
sensor coils that are induced by the B-fields produced by emitter
coils 824 within the formation. Each of the sensor coils 814 are
also coupled to a common node and are also oriented orthogonally
with respect to each other so as to match the orientations of the
emitter coils along each of the X, Y and Z axes. Sensor electronics
module 812 also couples to other electronics within the tool body
and forwards the detected signals generated by sensor coils 814 to
the tool body electronics for further processing.
[0034] It should be noted that although emitter 820 and sensor 810
are implemented using individual coils, those of ordinary skill
will recognize that other structures and configurations such as,
for example, dipoles and phased arrays may be suitable for use
within the emitters and sensors described herein, and all such
structures and configurations are within the scope of the present
disclosure.
[0035] Continuing to refer to FIG. 8, within sensor 810, sensor
electronics module 812 also couples to bucking coils 816, which are
also oriented and coupled to each other in a manner similar to the
coils within sensor 814. Each of sensor coils 816 is, however,
wound in the opposite direction relative to the corresponding
sensor coil 814, though their orientations are matched along each
of the X, Y and Z axes. Bucking coils 816 are also positioned
proximate to sensor coils 814 and between sensor coils 814 and
emitter coils 824. Bucking coils 816 thus generate a signal for
each orientation that is opposite in polarity from the
corresponding signal from sensor coils 814. In at least some
embodiments, the number of turns in each bucking coil is adjusted
to account for the difference in the distances between bucking
coils 816 and emitter coils 824 and the distances between sensor
coils 814 and emitter coils 824. As a result, the signals produced
by bucking coils 816 that are attributable to direct coupling with
emitter coils 824 will cancel the signals produced by sensor coils
814 that are also attributable to direct coupling with emitter 824.
Signals produced due to coupling through the formation between
emitter coils 824 and both sensor coils 814 and bucking coils 816,
however, will not cancel out and a difference signal representing
the induced B-field in the formation will be produced from the
combination of the corresponding sensor coil and bucking coil
signals for each orientation (X, Y and Z). Those of ordinary skill
in the art will recognize that many other techniques may be
suitable for canceling and/or blocking the effect of direct
coupling between emitter and sensor coils (e.g., electromagnetic
shielding between the emitter and sensor coils), and all such
techniques are within the scope of the present disclosure.
[0036] By mounting both the sensor coils 814 and the emitter coils
824 within transducer pad 800, and by canceling and/or blocking
direct coupling between the sensor and emitter coils (e.g., by
incorporating bucking coils 816 within the pad), it is possible to
maintain a relatively small vertical spacing between the sensor and
emitter coils and to increase the sensitivity of the logging tool.
Sensor/emitter coils vertical spacings of one inch or less are
possible with the tools, systems and methods described herein.
Reductions in the vertical spacing between sensor and emitter coils
produce a higher vertical resolution of the resulting borehole log.
This is due to the fact that as the distance from the emitter
decreases, the directionality of the relevant parameter (B-field,
electric current, etc.) is more pronounced, i.e., the difference in
magnitude of the primary parameter component relative to the other
two orthogonal components increases, as shown in FIG. 7. This also
increases the overall sensitivity of the tool. Increasing the
differences in such measurement thus helps to uniquely identify
properties such as electrical resistivity or conductivity and
electrical permittivity (i.e., the overall formation impedance) at
both a macro and micro level in specific directions with greater
precision, and to thus produce a full measurement tensor such as
the 3.times.3 measurement tensor previously described. Such a
measurement tensor enables the electrical anisotropy of the
surrounding formation to be characterized and quantified (e.g., by
determining the micro-impedance of the surrounding formation in
each of three orthogonal directions for each measurement sample).
In at least some illustrative embodiments, the components of the
tensor are expressed as complex values, wherein each complex
value's real component indicates the formation's resistivity or
conductivity and each complex value's imaginary component indicates
the electric permittivity of the formation.
[0037] The above-described techniques for producing a 3.times.3
measurement tensor are not limited to transducer pads that
incorporate inductive emitters and sensors. Transducer pads that
incorporate capacitive emitters and sensors (not shown) may be
configured and operated in a manner similar to the inductive
emitters and sensors, wherein time-variant electric fields
(E-fields) are induced into the surrounding formation in each of
the three orthogonal directions and similar micro-impedance
measurement samples are produced.
[0038] Galvanic emitters and sensors may also be incorporated into
a transducer pad, as shown in illustrative transducer pad 900 of
FIG. 9. Transducer pad 900 (shown with the pad facing forward)
includes dynamically configurable electrodes organized in an array.
As shown, each electrode set 1002 includes a central electrode 1004
surrounded by one or more focusing electrodes 1006, and each set
may be operated as either an emitter or a sensor. Alternatively,
selected electrodes may be hardwired to suitable electronics as an
emitter or sensor rather than being switched between emitter and
sensor configurations. The dynamic configuration enables a greater
flexibility, for example, in the number of directions in which
current can be detected, thereby increasing the data suitable for
use in an inversion to derive the localized formation tensor. The
selected emitter electrodes provide a static or low frequency
E-field (e.g., <100 Hz) to generate a localized current flow in
the surrounding formation. The current can flow to a distant return
electrode or between two selected emitter electrodes, and
appropriate switching enables sufficient measurements to be
obtained for the tensor inversion. The focusing electrodes can be
enabled or disabled to vary the depth of penetration of the current
into the formation, thereby providing additional measurements. The
measurements obtained by the selected sensor electrodes may be
voltage differentials or absolute voltages relative to the tool
ground.
[0039] It should be noted that while the above embodiments are
described within the context of wireline logging tool transducer
pads that contact the borehole wall, the emitter and sensor
configurations described may also be used with LWD tools such as
that shown in FIG. 4A. In such LWD tool embodiments, the
resistivity of the drilling fluid and the standoff distance between
the transducers and the borehole wall can affect the sampled
measurements, but both of these parameters may also be accounted
for by the inversion process described in more detail below.
[0040] As previously noted, emitter and sensor electronics modules
within the transducer pad coupled to electronics within the tool
body. The illustrative embodiment of FIG. 10 illustrates an example
of an anisotropy imaging system 1100, and shows both the downhole
system electronics (including the tool body electronics) and
surface system electronics. Downhole system 1120 includes four
transducer pads 1140 (similar to those already described) that each
includes emitters 1146 coupled to emitter electronics module 1142,
and sensors 1148 coupled to sensor electronics module 1144. The
emitter and sensor electronics modules couple to and communicate
with downhole hardware interface module 1138 within tool body 1130,
which provides an interface between the transducer pads 1140 and
downhole processor 1134.
[0041] Downhole processor 1134, which can include any of a wide
variety of processors and/or processing subsystems, executes
software that performs at least some of the control and data
acquisition tasks associated with controlling and acquiring data
from transducer pad 1140. The software executing on downhole
processor 1134, as well as the acquired data, is stored on downhole
memory/storage module 1136, which couples to downhole processor
1134 and can include any known data storage technology suitable for
use in a downhole tool environment. Downhole processor 1134 also
couples to downhole/surface interface module 1132, which in turn
couples to surface/downhole interface module 1114 within surface
system 1110 to provide a communication link between surface system
1110 and downhole system 1120.
[0042] Surface system 1110 includes surface processor 1116, which
couples to user interface 1112, surface/downhole interface module
1114 and surface memory/storage module 1118. Surface processor 1116
executes software stored within surface memory/storage module 1118
that performs processing on the data provided by downhole system
1120 via surface/downhole interface module 1114. Surface
memory/storage module 1118 may be any of a wide variety of memory
and/or storage device, or combinations thereof, and provides both
short-term (e.g., while the system is powered up) and long-term
(e.g., during periods when the system is powered down) program and
data storage. Data provided by downhole system 1120, as well as
data processed by surface processor 1116, may be stored on surface
memory/storage module 1118. User interface 1112 allows a user to
interact with surface system 1110 (and overall with anisotropy
imaging system 1100), providing both input devices suitable for
entering commands (e.g., a mouse and keyboard) and output devices
for displaying windows, menus and data to a user (e.g., displays
and printers).
[0043] The data acquired by downhole system 1120 is processed to
derive anisotropy data that can be presented to a user of system
1100. The processing is distributed between surface system 1110 and
downhole system 1120, and the present disclosure does not limit how
that distribution may be implemented. However, for purposes of
describing the functionality of the processing, the illustrative
embodiment presented performs the data acquisition and inversion
operations described below within downhole system 1120, and data
logging, presentation and long-term storage within surface system
1110.
[0044] As previously noted, each of the measurement samples
processed by anisotropy imaging system 1100 can be represented by a
measurement tensor M(z,.PHI..sub.t) with measurement tensor
components M.sub.ij(z,.PHI..sub.t). For each measurement tensor
component, i={x,y,z} and represents the orientation of the active
emitter when the measurement was taken, j={x,y,z} and represents
the orientation of the sensor that performed the measurement, z is
the borehole depth, and .PHI..sub.t is the azimuthal angle relative
to the tool axis. The flow of the measurement tensor data as it is
processed by anisotropy imaging system 1100 is shown in FIG. 11. A
measurement tensor is received (block 1202) and the measurement
tensor component values are adjusted to account for calibration and
temperature corrections (block 1204). In some cases where the
conductivity of the formation behaves linearly, it may also be
possible to adjust the measured values (block 1204) to control the
radial and vertical resolution of the measurements using software
focusing filters. Such filtering can also reduce the effect of the
borehole wall and the standoff of the tool from the borehole wall
(e.g., when incorporated into an LWD tool). Software focusing is
well known in the art and not discussed further.
[0045] Once the measurement tensor component values have been
adjusted (block 1204) an inversion process is performed (block
1208) whereby the adjusted measurement tensor component values are
iteratively compared against reference tensor component values from
a library (block 1206) or against reference tensor component values
produced by a forward model (block 1210). The formation parameters
for the library and/or model reference tensor component values
associated with the smallest tensor difference (described in more
detail below) are provided to surface system 1110 as the formation
parameter values associated with the depth and azimuth angle of the
adjusted measurement tensor. Surface system 1110 then present the
data to the user (block 1212) as, for example, the graphical logs
of FIG. 12. The data and the logs may both be saved on surface
memory/storage module 1118 for later retrieval and or additional
processing. In at least some illustrative embodiments, a
combination of a library lookup and a forward model calculation may
be used. For example, comparisons with a library may be used to
identify one or more parameter value ranges (horizontal and
vertical resistivity, relative dip, relative strike, etc.), after
which the model is iteratively applied over that range to identify
modeled reference tensor component values that more closely match
the adjusted measurement tensor component values.
[0046] The reference tensor component values provided by either a
library or a forward model are compared against the adjusted
measurement tensor component values by calculating a normalized
tensor difference between an adjusted measurement tensor and a
library-supplied or model-generated reference tensor. This
different magnitude is iteratively computed for each reference
tensor from the library or the model until a minimum difference
magnitude is identified. The parameter values corresponding to the
library/model reference tensor that produces the minimum difference
magnitude are provided as the parameters of the formation
corresponding to the borehole depth and azimuth of the adjusted
measured tensor. In at least some illustrative embodiments this
relationship is expressed as follows:
[ R h ( z , .PHI. t ) , R v ( z , .PHI. t ) , .theta. ( z , .PHI. t
) , .PHI. ( z , .PHI. t ) ] = arg R h , R v , .theta. , .PHI. [ min
( M ij ref ( R h , R v , .theta. , .PHI. ) - M ij adj ( z , .PHI. t
) M zz ref ( R h , R v , .theta. , .PHI. ) ) ] ( 1 )
##EQU00001##
[0047] where, [0048] R.sub.h is the horizontal resistivity; [0049]
R.sub.v is the vertical resistivity; [0050] .theta. is the relative
dip (to the tool); [0051] .PHI. is the relative strike (to the
tool); [0052] .PHI..sub.t is the tool measurement azimuth; [0053] z
is the borehole depth; [0054] M.sub.ij.sup.ref is the reference
tensor component ij (library or model); [0055] M.sub.ij .sup.adj is
the adjusted measurement tensor component ij; [0056] i is the
tensor component orientation index {x,y,z} of the emitter; and
[0057] j is the tensor component orientation index {x,y,z} of the
sensor. As previously noted the indices indicate the orientations
of the active emitter when the measurement was taken and of the
sensor providing the measurement. Thus, for example,
M.sub.zz.sup.ref represents a reference measurement for an active
emitter and a sensor both oriented in the z direction (here used
for normalization). Similarly, M.sub.xy.sup.adj is an adjusted
measurement taken by a sensor oriented along the y axis while an
emitter oriented along the x axis was active. Measurements can
include, but are not limited to, voltage, current, magnetic field
strength and electric field strength. For example, in the
embodiment of FIG. 8, voltage measurements may be provided by each
of the sensor coils 814 and compared against similar reference
voltage measurements.
[0058] It should be noted that to fully characterize the anisotropy
of the borehole measurements, both the tool measurement azimuth
.PHI..sub.t as well as the formation strike .PHI..sup.abs with
respect to earth are needed. In at least some illustrative
embodiments the formation strike .PHI..sup.abs is derived from the
tool measurement azimuth .PHI..sub.t and the relative formation
strike .PHI. using the following conversion equation:
.PHI..sup.abs(z, .PHI..sub.t)=.PHI.(z, .PHI..sub.t)-.PHI..sub.t
(2)
Also, additional parameters may be included in and provided by the
library and/or the model. Such parameters may include, for example,
the standoff distance between the transducer pad and borehole wall
and the mud resistivity for embodiments where the emitters and
sensors do not contact the wall.
[0059] The dielectric constant of the formation may also be
included in and provided by the library and/or model through the
use of multiple measurements taken at different frequencies. At
lower frequencies the response is primarily due to the resistivity
of the formation, while at higher frequencies the response is
primarily due to the reactance of the formation. In at least some
embodiments, additional measurements are made in various directions
as before but at multiple frequencies, enabling the anisotropy of
the dielectric constant to also be characterized. This
characterization may be derived from either a second separate
measurement tensor that includes the additional measurements for
each sample at a given azimuth and depth, or from a single higher
order measurement tensor that includes sufficient components to
derive both the electrical resistivity and permittivity anisotropy
of the formation. Anisotropic resistivity and dielectric values may
also be converted into properties of individual layers that make up
laminations present in the formation. For example, horizontal
resistivities, vertical resistivities, dielectric constants and
their volumetric ratios may be used to identify shale and sand
layers. Because the systems and methods described enable the
measurements to be resolved into at least three orthogonal
directions (e.g., two horizontal and one vertical), more complex
laminations and formations may be identified and characterized.
[0060] FIG. 13 shows an illustrative method for using the tools and
systems described above. An illustrative borehole imaging tool is
lowered into the borehole (block 1402), and as it is pulled back up
the borehole, the tool periodically induces fields in three
different directions within the formation for a given depth and
azimuth angle, each field induced during three separate time
periods (block 1404). During each time period, field measurement
samples are taken in all three directions (block 1406). The
measurements may be electric field measurements or magnetic field
measurements (or both), and may be expressed either directly as
field strength measurements or indirectly as corresponding
electrical current or electric potential measurements. A
measurement tensor is produced (e.g., a 3.times.3 voltage
measurement tensor) that is associated with a given borehole depth
and tool azimuth angle (block 1408). The borehole characteristics
at the given depth and azimuth angle are derived from the
measurement tensor (block 1410) by using, for example, the
inversion process described above. The derived data is then
presented to a user of the tool (block 1412), ending the method
(block 1414). FIG. 12 (previously described) shows an illustrative
example of the types of two-dimensional log formats that can be
used to present the data to a user.
[0061] Numerous other modifications, equivalents, and alternatives
will become apparent to those skilled in the art once the above
disclosure is fully appreciated. For example, although three
orthogonal emitters and sensors are used in a tri[[-]]axial
configuration in the embodiments described, different numbers of
emitters and/or sensors may also be used, and such emitters and/or
sensors may be configured in a non-orthogonal orientation. Also,
additional focusing and guard rings may be added to the galvanic
transducer pads described to provide additional control over the
direction of the current flowing through the formation to/from such
transducer pads. Further, although each type of emitter and sensor
(galvanic, capacitive and inductive) was discussed individually, at
least some embodiments combine several of these into a single
instrument and include combined concurrent measurements within the
measurement tensors. The programmable downhole processor is just
one example of a suitable downhole controller, and it could be
replaced or augmented with an integrated or hardwired controller.
It is intended that the following claims be interpreted to embrace
all such modifications, equivalents, and alternatives where
applicable.
* * * * *